eCFR for 30 CFR 250, subpart Q
eCFR 30 CFR 250 - subpart Q.docx
30 CFR part 250, subpart Q, Decommissioning Costs
eCFR for 30 CFR 250, subpart Q
OMB: 1014-0029
Electronic Code of Federal Regulations
Title
30: Mineral Resources Subpart Q—Decommissioning Activities Contents §250.1700 What
do the terms “decommissioning”, “obstructions”,
and “facility” mean? §250.1710 When
must I permanently plug all wells on a lease? §250.1721 If
I temporarily abandon a well that I plan to re-enter, what must I
do? Removing Platforms and Other Facilities §250.1725 When
do I have to remove platforms and other
facilities? Site Clearance for Wells, Platforms, and Other Facilities §250.1740 How
must I verify that the site of a permanently plugged well, removed
platform, or other removed facility is clear of
obstructions? §250.1750 When
may I decommission a pipeline in place? §250.1700 What do the terms “decommissioning”, “obstructions”, and “facility” mean? (a) Decommissioning means: (1) Ending oil, gas, or sulphur operations; and (2) Returning the lease or pipeline right-of-way to a condition that meets the requirements of regulations of BSEE and other agencies that have jurisdiction over decommissioning activities. (b) Obstructions mean structures, equipment, or objects that were used in oil, gas, or sulphur operations or marine growth that, if left in place, would hinder other users of the OCS. Obstructions may include, but are not limited to, shell mounds, wellheads, casing stubs, mud line suspensions, well protection devices, subsea trees, jumper assemblies, umbilicals, manifolds, termination skids, production and pipeline risers, platforms, templates, pilings, pipelines, pipeline valves, and power cables. (c) Facility means any installation other than a pipeline used for oil, gas, or sulphur activities that is permanently or temporarily attached to the seabed on the OCS. Facilities include production and pipeline risers, templates, pilings, and any other facility or equipment that constitutes an obstruction such as jumper assemblies, termination skids, umbilicals, anchors, and mooring lines. §250.1701 Who must meet the decommissioning obligations in this subpart? (a) Lessees and owners of operating rights are jointly and severally responsible for meeting decommissioning obligations for facilities on leases, including the obligations related to lease-term pipelines, as the obligations accrue and until each obligation is met. (b) All holders of a right-of-way are jointly and severally liable for meeting decommissioning obligations for facilities on their right-of-way, including right-of-way pipelines, as the obligations accrue and until each obligation is met. (c) In this subpart, the terms “you” or “I” refer to lessees and owners of operating rights, as to facilities installed under the authority of a lease, and to right-of-way holders as to facilities installed under the authority of a right-of-way. §250.1702 When do I accrue decommissioning obligations? You accrue decommissioning obligations when you do any of the following: (a) Drill a well; (b) Install a platform, pipeline, or other facility; (c) Create an obstruction to other users of the OCS; (d) Are or become a lessee or the owner of operating rights of a lease on which there is a well that has not been permanently plugged according to this subpart, a platform, a lease term pipeline, or other facility, or an obstruction; (e) Are or become the holder of a pipeline right-of-way on which there is a pipeline, platform, or other facility, or an obstruction; or (f) Re-enter a well that was previously plugged according to this subpart. §250.1703 What are the general requirements for decommissioning? When your facilities are no longer useful for operations, you must: (a) Get approval from the appropriate District Manager before decommissioning wells and from the Regional Supervisor before decommissioning platforms and pipelines or other facilities; (b) Permanently plug all wells; (c) Remove all platforms and other facilities, except as provided in §§250.1725(a) and 250.1730. (d) Decommission all pipelines; (e) Clear the seafloor of all obstructions created by your lease and pipeline right-of-way operations; and (f) Conduct all decommissioning activities in a manner that is safe, does not unreasonably interfere with other uses of the OCS, and does not cause undue or serious harm or damage to the human, marine, or coastal environment. §250.1704 When must I submit decommissioning applications and reports? You must submit decommissioning applications and receive approval and submit subsequent reports according to the table in this section. Decommissioning Applications and Reports Table
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50896, Aug. 22, 2012] §250.1705 What BOP information must I submit? If you plan to use a BOP for abandonment operations, your decommissioning application must include the following BOP descriptions: (a) A description of the BOP system and system components, including pressure ratings of BOP equipment and proposed BOP test pressures; (b) A schematic drawing of the BOP system that shows the inside diameter of the BOP stack, number and type of preventers, all control systems and pods, location of choke and kill lines, and associated valves; (c) Independent third-party verification and supporting documentation that show the blind-shear rams installed in the BOP stack are capable of shearing any drill pipe (including workstring and tubing) in the hole under maximum anticipated surface pressure. The documentation must include actual shearing and subsequent pressure integrity test results for the most rigid pipe to be used and calculations of shearing capacity of all pipe to be used in the well, including correction for Maximum Anticipated Surface Pressure (MASP); (d) When you use a subsea BOP stack, independent third-party verification that shows: (1) The BOP stack is designed for the specific equipment on the rig and for the specific well design; (2) The BOP stack has not been compromised or damaged from previous service; (3) The BOP stack will operate in the conditions in which it will be used; and (e) The qualifications of the independent third-party referenced in paragraphs (c) and (d) of this section including evidence that: (1) The independent third-party in this section is a technical classification society, or a licensed professional engineering firm, or a registered professional engineer capable of providing the verifications required under this part. (2) You must: (i) Include evidence that the registered professional engineer, or a technical classification society, or engineering firm you are using or its employees hold appropriate licenses to perform the verification in the appropriate jurisdiction, and evidence to demonstrate that the individual, society, or firm has the expertise and experience necessary to perform the required verifications. (ii) Ensure that an official representative of BSEE will have access to the location to witness any testing or inspections, and verify information submitted to BSEE. Prior to any shearing ram tests or inspections, you must notify the BSEE District Manager at least 72 hours in advance. [77 FR 50897, Aug. 22, 2012] §250.1706 What are the requirements for blowout prevention equipment? If you use a BOP for any well abandonment operations, your BOP must meet the following requirements: (a) The BOP system, system components, and related well-control equipment must be designed, used, maintained, and tested in a manner necessary to assure well-control in foreseeable conditions and circumstances, including subfreezing conditions. The working pressure rating of the BOP system and system components must exceed the expected surface pressure to which they may be subjected. If the expected surface pressure exceeds the rated working pressure of the annular preventer, you must submit with Form BSEE-0124, requesting approval of the well abandonment operations, a well-control procedure that indicates how the annular preventer will be utilized, and the pressure limitations that will be applied during each mode of pressure control. (b) The minimum BOP system for well abandonment operations with the tree removed must meet the appropriate standards from the following table:
(c) The BOP systems for well abandonment operations with the tree removed must be equipped with the following: (1) A hydraulic-actuating system that provides sufficient accumulator capacity to supply 1.5 times the volume necessary to close all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system. Accumulator regulators supplied by rig air and without a secondary source of pneumatic supply, must be equipped with manual overrides, or alternately, other devices provided to ensure capability of hydraulic operations if rig air is lost; (2) A secondary power source, independent from the primary power source, with sufficient capacity to close all BOP system components and hold them closed; (3) Locking devices for the pipe-ram preventers; (4) At least one remote BOP-control station and one BOP-control station on the rig floor; and (5) A choke line and a kill line each equipped with two full opening valves and a choke manifold. At least one of the valves on the choke-line must be remotely controlled. At least one of the valves on the kill line must be remotely controlled, except that a check valve on the kill line in lieu of the remotely controlled valve may be installed, provided two readily accessible manual valves are in place and the check valve is placed between the manual valves and the pump. This equipment must have a pressure rating at least equivalent to the ram preventers. You must install the choke line above the bottom ram and may install the kill line below the bottom ram. (d) The minimum BOP system components for well abandonment operations with the tree in place and performed through the wellhead inside of conventional tubing using small-diameter jointed pipe (usually 3⁄4 inch to 11⁄4 inch) as a work string, i.e., small-tubing operations, must include the following: (1) Two sets of pipe rams, and (2) One set of blind rams. (e) The subsea BOP system for well abandonment operations must meet the requirements in §250.442 of this part. (f) For coiled tubing operations with the production tree in place, you must meet the following minimum requirements for the BOP system: (1) BOP system components must be in the following order from the top down:
(2) You may use a set of hydraulically-operated combination rams for the blind rams and shear rams. (3) You may use a set of hydraulically-operated combination rams for the hydraulic two-way slip rams and the hydraulically-operated pipe rams. (4) You must attach a dual check valve assembly to the coiled tubing connector at the downhole end of the coiled tubing string for all coiled tubing well abandonment operations. If you plan to conduct operations without downhole check valves, you must describe alternate procedures and equipment in Form BSEE-0124, Application for Permit to Modify, and have it approved by the BSEE District Manager. (5) You must have a kill line and a separate choke line. You must equip each line with two full-opening valves and at least one of the valves must be remotely controlled. You may use a manual valve instead of the remotely controlled valve on the kill line if you install a check valve between the two full-opening manual valves and the pump or manifold. The valves must have a working pressure rating equal to or greater than the working pressure rating of the connection to which they are attached, and you must install them between the well-control stack and the choke or kill line. For operations with expected surface pressures greater than 3,500 psi, the kill line must be connected to a pump or manifold. You must not use the kill line inlet on the BOP stack for taking fluid returns from the wellbore. (6) You must have a hydraulic-actuating system that provides sufficient accumulator capacity to close-open-close each component in the BOP stack. This cycle must be completed with at least 200 psi above the pre-charge pressure, without assistance from a charging system. (7) All connections used in the surface BOP system from the tree to the uppermost required ram must be flanged, including the connections between the well-control stack and the first full-opening valve on the choke line and the kill line. (g) The minimum BOP system components for well abandonment operations with the tree in place and performed by moving tubing or drill pipe in or out of a well under pressure utilizing equipment specifically designed for that purpose, i.e., snubbing operations, must include the following: (1) One set of pipe rams hydraulically operated, and (2) Two sets of stripper-type pipe rams hydraulically operated with spacer spool. (h) An inside BOP or a spring-loaded, back-pressure safety valve, and an essentially full-opening, work-string safety valve in the open position must be maintained on the rig floor at all times during well abandonment operations when the tree is removed or during well abandonment operations with the tree installed and using small tubing as the work string. A wrench to fit the work-string safety valve must be readily available. Proper connections must be readily available for inserting valves in the work string. The full-opening safety valve is not required for coiled tubing or snubbing operations. [77 FR 50897, Aug. 22, 2012] §250.1707 What are the requirements for blowout preventer system testing, records, and drills? (a) BOP pressure tests. When you pressure test the BOP system, you must conduct a low-pressure test and a high-pressure test for each component. You must conduct the low-pressure test before the high-pressure test. For purposes of this section, BOP system components include ram-type BOP's, related control equipment, choke and kill lines, and valves, manifolds, strippers, and safety valves. Surface BOP systems must be pressure tested with water. (1) Low pressure tests. You must successfully test all BOP system components to a low pressure between 200 and 300 psi. Any initial pressure equal to or greater than 300 psi must be bled back to a pressure between 200 and 300 psi before starting the test. If the initial pressure exceeds 500 psi, you must bleed back to zero before starting the test. (2) High pressure tests. You must successfully test all BOP system components to the rated working pressure of the BOP equipment, or as otherwise approved by the BSEE District Manager. You must successfully test the annular-type BOP at 70 percent of its rated working pressure or as otherwise approved by the BSEE District Manager. (3) Other testing requirements. You must test variable bore pipe rams against the largest and smallest sizes of tubulars in use (jointed pipe, seamless pipe) in the well. (b) You must test the BOP systems at the following times: (1) When installed; (2) At least every 7 days, alternating between control stations and at staggered intervals to allow each crew to operate the equipment. If either control system is not functional, further operations must be suspended until the nonfunctional system is operable. The test every 7 days is not required for blind or blind-shear rams. The blind or blind-shear rams must be tested at least once every 30 days during operation. A longer period between blowout preventer tests is allowed when there is a stuck pipe or pressure-control operation and remedial efforts are being performed. The tests must be conducted as soon as possible and before normal operations resume. The reason for postponing testing must be entered into the operations log. The BSEE District Manager may require alternate test frequencies if conditions or BOP performance warrant. (3) Following repairs that require disconnecting a pressure seal in the assembly, the affected seal will be pressure tested. (c) All personnel engaged in well abandonment operations must participate in a weekly BOP drill to familiarize crew members with appropriate safety measures. (d) You may conduct a stump test for the BOP system on location. A plan describing the stump test procedures must be included in your Application for Permit to Modify, Form BSEE-0124, and must be approved by the BSEE District Manager. (e) You must test the coiled tubing connector to a low pressure of 200 to 300 psi, followed by a high pressure test to the rated working pressure of the connector or the expected surface pressure, whichever is less. You must successfully pressure test the dual check valves to the rated working pressure of the connector, the rated working pressure of the dual check valve, expected surface pressure, or the collapse pressure of the coiled tubing, whichever is less. (f) You must record test pressures during BOP and coiled tubing tests on a pressure chart, or with a digital recorder, unless otherwise approved by the BSEE District Manager. The test interval for each BOP system component must be 5 minutes, except for coiled tubing operations, which must include a 10 minute high-pressure test for the coiled tubing string. Your representative at the facility must certify that the charts are correct. (g) The time, date, and results of all pressure tests, actuations, inspections, and crew drills of the BOP system, system components, and marine risers must be recorded in the operations log. The BOP tests must be documented in accordance with the following: (1) The documentation must indicate the sequential order of BOP and auxiliary equipment testing, the pressure, and duration of each test. As an alternate, the documentation in the operations log may reference a BOP test plan that contains the required information and is retained on file at the facility. (2) The control station used during the test must be identified in the operations log. For a subsea system, the pod used during the test must be identified in the operations log. (3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to remedy such problems or irregularities, must be noted in the operations log. (4) Documentation required to be entered in the operations log may instead be referenced in the operations log. You must make all records including pressure charts, operations log, and referenced documents pertaining to BOP tests, actuations, and inspections, available for BSEE review at the facility for the duration of well abandonment activity. Following completion of the well abandonment activity, you must retain all such records for a period of two years at the facility, at the lessee's field office nearest the OCS facility, or at another location conveniently available to the BSEE District Manager. (h) Stump test a subsea BOP system before installation. You must use water to conduct this test. You may use drilling fluids to conduct subsequent tests of a subsea BOP system. You must stump test the subsea BOP within 30 days of the initial test on the seafloor. You must: (1) Test all ROV intervention functions on your subsea BOP stack during the stump test. Each ROV must be fully compatible with the BOP stack ROV intervention panels. You must also test and verify closure of at least one set of rams during the initial test on the seafloor. You must submit test procedures, including how you will test each ROV function, with your APM for BSEE District Manager approval. You must: (i) Ensure that the ROV hot stabs are function tested and are capable of actuating, at a minimum, one set of pipe rams and one set of blind-shear rams and unlatching the LMRP; (ii) Document all your test results and make them available to BSEE upon request; and (2) Function test autoshear and deadman systems on your subsea BOP stack during the stump test. You must also test the deadman system and verify closure of at least one set of blind-shear rams during the initial test on the seafloor. When you conduct the initial deadman system test on the seafloor you must ensure the well is secure and, if hydrocarbons have been present, appropriate barriers are in place to isolate hydrocarbons from the wellhead. You must also have an ROV on bottom during the test. You must: (i) Submit test procedures with your APM for BSEE District Manager approval. The procedures for these function tests must include documentation of the controls and circuitry of the system utilized during each test. The procedure must also describe how the ROV will be utilized during this operation. (ii) Document the results of each test and make them available to BSEE upon request. [77 FR 50899, Aug. 22, 2012] §250.1708 What are my BOP inspection and maintenance requirements? (a) BOP inspections. (1) You must inspect your BOP system to ensure that the equipment functions properly. The BOP inspections must meet or exceed the provisions of Sections 17.10 and 18.10, Inspections, described in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells (incorporated by reference as specified in §250.198). You must document how you met or exceeded the provisions of Sections 17.10 and 18.10 described in API RP 53, document the procedures used, record the results, and make the records available to BSEE upon request. You must maintain your records on the rig for 2 years from the date the records are created, or for a longer period if directed by BSEE. (2) You must visually inspect your BOP system and marine riser at least once every 3 days if weather and sea conditions permit. You may use television cameras to inspect this equipment. The BSEE District Manager may approve alternate methods and frequencies to inspect a marine riser. (b) BOP maintenance. You must maintain your BOP system to ensure that the equipment functions properly. The BOP maintenance must meet or exceed the provisions of Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, Quality Management, described in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells (incorporated by reference as specified in §250.198). You must document how you met or exceeded the provisions of Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, Quality Management, described in API RP 53, document the procedures used, record the results, and make the records available to BSEE upon request. You must maintain your records on the rig for 2 years from the date the records are created, or for a longer period if directed by BSEE. [77 FR 50900, Aug. 22, 2012] §250.1709 What are my well-control fluid requirements? Before you displace kill-weight fluid from the wellbore and/or riser to an underbalanced state, you must obtain approval from the BSEE District Manager. To obtain approval, you must submit with your APM, your reasons for displacing the kill-weight fluid and provide detailed step-by-step written procedures describing how you will safely displace these fluids. The step-by-step displacement procedures must address the following: (a) Number and type of independent barriers, as described in §250.420(b)(3), that are in place for each flow path that requires such barriers, (b) Tests you will conduct to ensure integrity of independent barriers, (c) BOP procedures you will use while displacing kill weight fluids, and (d) Procedures you will use to monitor the volumes and rates of fluids entering and leaving the wellbore. [77 FR 50900, Aug. 22, 2012] §250.1710 When must I permanently plug all wells on a lease? You must permanently plug all wells on a lease within 1 year after the lease terminates. §250.1711 When will BSEE order me to permanently plug a well? BSEE will order you to permanently plug a well if that well: (a) Poses a hazard to safety or the environment; or (b) Is not useful for lease operations and is not capable of oil, gas, or sulphur production in paying quantities. §250.1712 What information must I submit before I permanently plug a well or zone? Before you permanently plug a well or zone, you must submit form BSEE-0124, Application for Permit to Modify, to the appropriate District Manager and receive approval. A request for approval must contain the following information: (a) The reason you are plugging the well (or zone), for completions with production amounts specified by the Regional Supervisor, along with substantiating information demonstrating its lack of capacity for further profitable production of oil, gas, or sulfur; (b) Recent well test data and pressure data, if available; (c) Maximum possible surface pressure, and how it was determined; (d) Type and weight of well-control fluid you will use; (e) A description of the work; (f) A current and proposed well schematic and description that includes: (1) Well depth; (2) All perforated intervals that have not been plugged; (3) Casing and tubing depths and details; (4) Subsurface equipment; (5) Estimated tops of cement (and the basis of the estimate) in each casing annulus; (6) Plug locations; (7) Plug types; (8) Plug lengths; (9) Properties of mud and cement to be used; (10) Perforating and casing cutting plans; (11) Plug testing plans; (12) Casing removal (including information on explosives, if used); (13) Proposed casing removal depth; and (14) Your plans to protect archaeological and sensitive biological features, including anchor damage during plugging operations, a brief assessment of the environmental impacts of the plugging operations, and the procedures and mitigation measures you will take to minimize such impacts; and (g) Certification by a Registered Professional Engineer of the well abandonment design and procedures and that all plugs meet the requirements in the table in §250.1715. In addition to the requirements of §250.1715, the Registered Professional Engineer must also certify the design will include two independent barriers, one of which must be a mechanical barrier, in the center wellbore as described in §250.420(b)(3). The Registered Professional Engineer must be registered in a State of the United States and have sufficient expertise and experience to perform the certification. You must submit this certification with your APM (Form BSEE-0124). [76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012] §250.1713 Must I notify BSEE before I begin well plugging operations? You must notify the appropriate District Manager at least 48 hours before beginning operations to permanently plug a well. §250.1714 What must I accomplish with well plugs? You must ensure that all well plugs: (a) Provide downhole isolation of hydrocarbon and sulphur zones; (b) Protect freshwater aquifers; and (c) Prevent migration of formation fluids within the wellbore or to the seafloor. §250.1715 How must I permanently plug a well? (a) You must permanently plug wells according to the table in this section. The District Manager may require additional well plugs as necessary. Permanent Well Plugging Requirements
(b) You must test the first plug below the surface plug and all plugs in lost circulation areas that are in open hole. The plug must pass one of the following tests to verify plug integrity: (1) A pipe weight of at least 15,000 pounds on the plug; or (2) A pump pressure of at least 1,000 pounds per square inch. Ensure that the pressure does not drop more than 10 percent in 15 minutes. The District Manager may require you to tests other plug(s). [76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012] §250.1716 To what depth must I remove wellheads and casings? (a) Unless the District Manager approves an alternate depth under paragraph (b) of this section, you must remove all wellheads and casings to at least 15 feet below the mud line. (b) The District Manager may approve an alternate removal depth if: (1) The wellhead or casing would not become an obstruction to other users of the seafloor or area, and geotechnical and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not expected; or (2) You determine, and BSEE concurs, that you must use divers, and the seafloor sediment stability poses safety concerns; or (3) The water depth is greater than 800 meters (2,624 feet). §250.1717 After I permanently plug a well, what information must I submit? Within 30 days after you permanently plug a well, you must submit form BSEE-0124, Application for Permit to Modify (subsequent report), to the appropriate District Manager, and include the following information: (a) Information included in §250.1712 with a final well schematic; (b) Description of the plugging work; (c) Nature and quantities of material used in the plugs; and (d) If you cut and pulled any casing string, the following information: (1) A description of the methods used (including information on explosives, if used); (2) Size and amount of casing removed; and (3) Casing removal depth. §250.1721 If I temporarily abandon a well that I plan to re-enter, what must I do? You may temporarily abandon a well when it is necessary for proper development and production of a lease. To temporarily abandon a well, you must do all of the following: (a) Submit form BSEE-0124, Application for Permit to Modify, and the applicable information required by §250.1712 to the appropriate District Manager and receive approval; (b) Adhere to the plugging and testing requirements for permanently plugged wells listed in the table in §250.1715, except for §250.1715(a)(8). You do not need to sever the casings, remove the wellhead, or clear the site; (c) Set a bridge plug or a cement plug at least 100-feet long at the base of the deepest casing string, unless the casing string has been cemented and has not been drilled out. If a cement plug is set, it is not necessary for the cement plug to extend below the casing shoe into the open hole; (d) Set a retrievable or a permanent-type bridge plug or a cement plug at least 100 feet long in the inner-most casing. The top of the bridge plug or cement plug must be no more than 1,000 feet below the mud line. BSEE may consider approving alternate requirements for subsea wells case-by-case; (e) Identify and report subsea wellheads, casing stubs, or other obstructions that extend above the mud line according to U.S. Coast Guard (USCG) requirements; (f) Except in water depths greater than 300 feet, protect subsea wellheads, casing stubs, mud line suspensions, or other obstructions remaining above the seafloor by using one of the following methods, as approved by the District Manager or Regional Supervisor: (1) A caisson designed according to 30 CFR 250, subpart I, and equipped with aids to navigation; (2) A jacket designed according to 30 CFR 250, subpart I, and equipped with aids to navigation; or (3) A subsea protective device that meets the requirements in §250.1722. (g) Within 30 days after you temporarily plug a well, you must submit form BSEE-0124, Application for Permit to Modify (subsequent report), and include the following information: (1) Information included in §250.1712 with a well schematic; (2) Information required by §250.1717(b), (c), and (d); and (3) A description of any remaining subsea wellheads, casing stubs, mudline suspension equipment, or other obstructions that extend above the seafloor; and (h) Submit certification by a Registered Professional Engineer of the well abandonment design and procedures and that all plugs meet the requirements of paragraph (b) of this section. In addition to the requirements of paragraph (b) of this section, the Registered Professional Engineer must also certify the design will include two independent barriers, one of which must be a mechanical barrier, in the center wellbore as described in §250.420(b)(3). The Registered Professional Engineer must be registered in a State of the United States and have sufficient expertise and experience to perform the certification. You must submit this certification with your APM (Form BSEE-0124) required by §250.1712 of this part. [76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012] §250.1722 If I install a subsea protective device, what requirements must I meet? If you install a subsea protective device under §250.1721(f)(3), you must install it in a manner that allows fishing gear to pass over the obstruction without damage to the obstruction, the protective device, or the fishing gear. (a) Use form BSEE-0124, Application for Permit to Modify to request approval from the appropriate District Manager to install a subsea protective device. (b) The protective device may not extend more than 10 feet above the seafloor (unless BSEE approves otherwise). (c) You must trawl over the protective device when you install it (adhere to the requirements at §250.1741(d) through (h)). If the trawl does not pass over the protective device or causes damage to it, you must notify the appropriate District Manager within 5 days and perform remedial action within 30 days of the trawl; (d) Within 30 days after you complete the trawling test described in paragraph (c) of this section, submit a report to the appropriate District Manager using form BSEE-0124, Application for Permit to Modify that includes the following: (1) The date(s) the trawling test was performed and the vessel that was used; (2) A plat at an appropriate scale showing the trawl lines; (3) A description of the trawling operation and the net(s) that were used; (4) An estimate by the trawling contractor of the seafloor penetration depth achieved by the trawl; (5) A summary of the results of the trawling test including a discussion of any snags and interruptions, a description of any damage to the protective covering, the casing stub or mud line suspension equipment, or the trawl, and a discussion of any snag removals requiring diver assistance; and (6) A letter signed by your authorized representative stating that he/she witnessed the trawling test. (e) If a temporarily abandoned well is protected by a subsea device installed in a water depth less than 100 feet, mark the site with a buoy installed according to the USCG requirements. (f) Provide annual reports to the Regional Supervisor describing your plans to either re-enter and complete the well or to permanently plug the well. (g) Ensure that all subsea wellheads, casing stubs, mud line suspensions, or other obstructions in water depths less than 300 feet remain protected. (1) To confirm that the subsea protective covering remains properly installed, either conduct a visual inspection or perform a trawl test at least annually. (2) If the inspection reveals that a casing stub or mud line suspension is no longer properly protected, or if the trawl does not pass over the subsea protective covering without causing damage to the covering, the casing stub or mud line suspension equipment, or the trawl, notify the appropriate District Manager within 5 days, and perform the necessary remedial work within 30 days of discovery of the problem. (3) In your annual report required by paragraph (f) of this section, include the inspection date, results, and method used and a description of any remedial work you will perform or have performed. (h) You may request approval to waive the trawling test required by paragraph (c) of this section if you plan to use either: (1) A buoy with automatic tracking capabilities installed and maintained according to USCG requirements at 33 CFR part 67 (or its successor); or (2) A design and installation method that has been proven successful by trawl testing of previous protective devices of the same design and installed in areas with similar bottom conditions. §250.1723 What must I do when it is no longer necessary to maintain a well in temporary abandoned status? If you or BSEE determines that continued maintenance of a well in a temporary abandoned status is not necessary for the proper development or production of a lease, you must: (a) Promptly and permanently plug the well according to §250.1715; (b) Remove any casing stub or mud line suspension equipment and any subsea protective covering. You must submit a request for approval to perform such work to the appropriate District Manager using form BSEE-0124, Application for Permit to Modify; and (c) Clear the well site according to §§250.1740 through 250.1742. Removing Platforms and Other Facilities §250.1725 When do I have to remove platforms and other facilities? (a) You must remove all platforms and other facilities within 1 year after the lease or pipeline right-of-way terminates, unless you receive approval to maintain the structure to conduct other activities. Platforms include production platforms, well jackets, single-well caissons, and pipeline accessory platforms. Other activities include those supporting OCS oil and gas production and transportation, as well as other energy-related or marine-related uses (including LNG) for which adequate financial assurance for decommissioning has been provided to a Federal agency which has given BSEE a commitment that it has and will exercise authority to compel the performance of decommissioning within a time following cessation of the new use acceptable to BSEE. The approval will specify: (1) Whether you must continue to maintain any financial assurance for decommissioning; and (2) Whether, and under what circumstances, you must perform any decommissioning not performed by the new facility owner/user. (b) Before you may remove a platform or other facility, you must submit a final removal application to the Regional Supervisor for approval and include the information listed in §250.1727. (c) You must remove a platform or other facility according to the approved application. (d) You must flush all production risers with seawater before you remove them. (e) You must notify the Regional Supervisor at least 48 hours before you begin the removal operations. §250.1726 When must I submit an initial platform removal application and what must it include? An initial platform removal application is required only for leases and pipeline rights-of-way in the Pacific OCS Region or the Alaska OCS Region. It must include the following information: (a) Platform or other facility removal procedures, including the types of vessels and equipment you will use; (b) Facilities (including pipelines) you plan to remove or leave in place; (c) Platform or other facility transportation and disposal plans; (d) Plans to protect marine life and the environment during decommissioning operations, including a brief assessment of the environmental impacts of the operations, and procedures and mitigation measures that you will take to minimize the impacts; and (e) A projected decommissioning schedule. §250.1727 What information must I include in my final application to remove a platform or other facility? You must submit to the Regional Supervisor, a final application for approval to remove a platform or other facility. Your application must be accompanied by payment of the service fee listed in §250.125. If you are proposing to use explosives, provide three copies of the application. If you are not proposing to use explosives, provide two copies of the application. Include the following information in the final removal application, as applicable: (a) Identification of the applicant including: (1) Lease operator/pipeline right-of-way holder; (2) Address; (3) Contact person and telephone number; and (4) Shore base. (b) Identification of the structure you are removing including: (1) Platform Name/BSEE Complex ID Number; (2) Location (lease/right-of-way, area, block, and block coordinates); (3) Date installed (year); (4) Proposed date of removal (Month/Year); and (5) Water depth. (c) Description of the structure you are removing including: (1) Configuration (attach a photograph or a diagram); (2) Size; (3) Number of legs/casings/pilings; (4) Diameter and wall thickness of legs/casings/pilings; (5) Whether piles are grouted inside or outside; (6) Brief description of soil composition and condition; (7) The sizes and weights of the jacket, topsides (by module), conductors, and pilings; and (8) The maximum removal lift weight and estimated number of main lifts to remove the structure. (d) A description, including anchor pattern, of the vessel(s) you will use to remove the structure. (e) Identification of the purpose, including: (1) Lease expiration/right-of-way relinquishment date; and (2) Reason for removing the structure. (f) A description of the removal method, including: (1) A brief description of the method you will use; (2) If you are using explosives, the following: (i) Type of explosives; (ii) Number and sizes of charges; (iii) Whether you are using single shot or multiple shots; (iv) If multiple shots, the sequence and timing of detonations; (v) Whether you are using a bulk or shaped charge; (vi) Depth of detonation below the mud line; and (vii) Whether you are placing the explosives inside or outside of the pilings; (3) If you will use divers or acoustic devices to conduct a pre-removal survey to detect the presence of turtles and marine mammals, a description of the proposed detection method; and (4) A statement whether or not you will use transducers to measure the pressure and impulse of the detonations. (g) Your plans for transportation and disposal (including as an artificial reef) or salvage of the removed platform. (h) If available, the results of any recent biological surveys conducted in the vicinity of the structure and recent observations of turtles or marine mammals at the structure site. (i) Your plans to protect archaeological and sensitive biological features during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation measures you will take to minimize such impacts. (j) A statement whether or not you will use divers to survey the area after removal to determine any effects on marine life. §250.1728 To what depth must I remove a platform or other facility? (a) Unless the Regional Supervisor approves an alternate depth under paragraph (b) of this section, you must remove all platforms and other facilities (including templates and pilings) to at least 15 feet below the mud line. (b) The Regional Supervisor may approve an alternate removal depth if: (1) The remaining structure would not become an obstruction to other users of the seafloor or area, and geotechnical and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not expected; or (2) You determine, and BSEE concurs, that you must use divers and the seafloor sediment stability poses safety concerns; or (3) The water depth is greater than 800 meters (2,624 feet). §250.1729 After I remove a platform or other facility, what information must I submit? Within 30 days after you remove a platform or other facility, you must submit a written report to the Regional Supervisor that includes the following: (a) A summary of the removal operation including the date it was completed; (b) A description of any mitigation measures you took; and (c) A statement signed by your authorized representative that certifies that the types and amount of explosives you used in removing the platform or other facility were consistent with those set forth in the approved removal application. §250.1730 When might BSEE approve partial structure removal or toppling in place? The Regional Supervisor may grant a departure from the requirement to remove a platform or other facility by approving partial structure removal or toppling in place for conversion to an artificial reef if you meet the following conditions: (a) The structure becomes part of a State artificial reef program, and the responsible State agency acquires a permit from the U.S. Army Corps of Engineers and accepts title and liability for the structure; and (b) You satisfy any U.S. Coast Guard (USCG) navigational requirements for the structure. §250.1731 Who is responsible for decommissioning an OCS facility subject to an Alternate Use RUE? (a) The holder of an Alternate Use RUE issued under 30 CFR part 585 is responsible for all decommissioning obligations that accrue following the issuance of the Alternate Use RUE and which pertain to the Alternate Use RUE. See 30 CFR part 585, subpart J, for additional information concerning the decommissioning responsibilities of an Alternate Use RUE grant holder. (b) The lessee under the lease originally issued under 30 CFR part 556 will remain responsible for decommissioning obligations that accrued before issuance of the Alternate Use RUE, as well as for decommissioning obligations that accrue following issuance of the Alternate Use RUE to the extent associated with continued activities authorized under this part. (c) If a lease issued under 30 CFR part 556 is cancelled or otherwise terminated under any provision of this subchapter, the lessee, upon our approval, may defer removal of any OCS facility within the lease area that is subject to an Alternate Use RUE. If we elect to grant such a deferral, the lessee remains responsible for removing the facility upon termination of the Alternate Use RUE and will be required to retain sufficient bonding or other financial assurances to ensure that the structure is removed or otherwise decommissioned in accordance with the provisions of this subpart. Site Clearance for Wells, Platforms, and Other Facilities §250.1740 How must I verify that the site of a permanently plugged well, removed platform, or other removed facility is clear of obstructions? Within 60 days after you permanently plug a well or remove a platform or other facility, you must verify that the site is clear of obstructions by using one of the following methods: (a) For a well site, you must either: (1) Drag a trawl over the site; (2) Scan across the location using sonar equipment; (3) Inspect the site using a diver; (4) Videotape the site using a camera on a remotely operated vehicle (ROV); or (5) Use another method approved by the District Manager if the particular site conditions warrant. (b) For a platform or other facility site in water depths less than 300 feet, you must drag a trawl over the site. (c) For a platform or other facility site in water depths 300 feet or more, you must either: (1) Drag a trawl over the site; (2) Scan across the site using sonar equipment; or (3) Use another method approved by the Regional Supervisor if the particular site conditions warrant. §250.1741 If I drag a trawl across a site, what requirements must I meet? If you drag a trawl across the site in accordance with §250.1740, you must meet all of the requirements of this section. (a) You must drag the trawl in a grid-like pattern as shown in the following table:
(b) You must trawl 100 percent of the limits described in paragraph (a) of this section in two directions. (c) You must mark the area to be cleared as a hazard to navigation according to USCG requirements until you complete the site clearance procedures. (d) You must use a trawling vessel equipped with a calibrated navigational positioning system capable of providing position accuracy of ±30 feet. (e) You must use a trawling net that is representative of those used in the commercial fishing industry (one that has a net strength equal or greater than that provided by No. 18 twine). (f) You must ensure that you trawl no closer than 300 feet from a shipwreck, and 500 feet from a sensitive biological feature. (g) If you trawl near an active pipeline, you must meet the requirements in the following table:
(h) You must ensure that any trawling contractor you may use: (1) Has no corporate or other financial ties to you; and (2) Has a valid commercial trawling license for both the vessel and its captain. §250.1742 What other methods can I use to verify that a site is clear? If you do not trawl a site, you can verify that the site is clear of obstructions by using any of the methods shown in the following table:
§250.1743 How do I certify that a site is clear of obstructions? (a) For a well site, you must submit to the appropriate District Manager within 30 days after you complete the verification activities a form BSEE-0124, Application for Permit to Modify, to include the following information: (1) A signed certification that the well site area is cleared of all obstructions; (2) The date the verification work was performed and the vessel used; (3) The extent of the area surveyed; (4) The survey method used; (5) The results of the survey, including a list of any debris removed or a statement from the trawling contractor that no objects were recovered; and (6) A post-trawling job plot or map showing the trawled area. (b) For a platform or other facility site, you must submit the following information to the appropriate Regional Supervisor within 30 days after you complete the verification activities: (1) A letter signed by an authorized company official certifying that the platform or other facility site area is cleared of all obstructions and that a company representative witnessed the verification activities; (2) A letter signed by an authorized official of the company that performed the verification work for you certifying that it cleared the platform or other facility site area of all obstructions; (3) The date the verification work was performed and the vessel used; (4) The extent of the area surveyed; (5) The survey method used; (6) The results of the survey, including a list of any debris removed or a statement from the trawling contractor that no objects were recovered; and (7) A post-trawling job plot or map showing the trawled area. §250.1750 When may I decommission a pipeline in place? You may decommission a pipeline in place when the Regional Supervisor determines that the pipeline does not constitute a hazard (obstruction) to navigation and commercial fishing operations, unduly interfere with other uses of the OCS, or have adverse environmental effects. §250.1751 How do I decommission a pipeline in place? You must do the following to decommission a pipeline in place: (a) Submit a pipeline decommissioning application in triplicate to the Regional Supervisor for approval. Your application must be accompanied by payment of the service fee listed in §250.125. Your application must include the following information: (1) Reason for the operation; (2) Proposed decommissioning procedures; (3) Length (feet) of segment to be decommissioned; and (4) Length (feet) of segment remaining. (b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical; (c) Flush the pipeline; (d) Fill the pipeline with seawater; (e) Cut and plug each end of the pipeline; (f) Bury each end of the pipeline at least 3 feet below the seafloor or cover each end with protective concrete mats, if required by the Regional Supervisor; and (g) Remove all pipeline valves and other fittings that could unduly interfere with other uses of the OCS. §250.1752 How do I remove a pipeline? Before removing a pipeline, you must: (a) Submit a pipeline removal application in triplicate to the Regional Supervisor for approval. Your application must be accompanied by payment of the service fee listed in §250.125. Your application must include the following information: (1) Proposed removal procedures; (2) If the Regional Supervisor requires it, a description, including anchor pattern(s), of the vessel(s) you will use to remove the pipeline; (3) Length (feet) to be removed; (4) Length (feet) of the segment that will remain in place; (5) Plans for transportation of the removed pipe for disposal or salvage; (6) Plans to protect archaeological and sensitive biological features during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation measures that you will take to minimize such impacts; and (7) Projected removal schedule and duration. (b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical; and (c) Flush the pipeline. §250.1753 After I decommission a pipeline, what information must I submit? Within 30 days after you decommission a pipeline, you must submit a written report to the Regional Supervisor that includes the following: (a) A summary of the decommissioning operation including the date it was completed; (b) A description of any mitigation measures you took; and (c) A statement signed by your authorized representative that certifies that the pipeline was decommissioned according to the approved application. §250.1754 When must I remove a pipeline decommissioned in place? You must remove a pipeline decommissioned in place if the Regional Supervisor determines that the pipeline is an obstruction.
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| File Type | application/vnd.openxmlformats-officedocument.wordprocessingml.document |
| Author | blundon |
| File Modified | 0000-00-00 |
| File Created | 2021-01-24 |
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